Improvements in in situ upgrading via hot fluid injection

ABSTRACT

The invention relates to systems, apparatus and methods for integrated recovery and in-situ (in reservoir) upgrading of heavy oil and oil sand bitumens. The systems, apparatus and methods enable enhanced recovery of heavy oil in a production well by introducing a hot hydrocarbon fluid from a mobile reservoir into the production well under conditions to promote hydrocarbon upgrading. The methods may further include introducing hydrogen and a catalyst together with the injection of the hot fluid into the production well to further promote hydrocarbon upgrading reactions. In addition, the invention relates to enhanced oil production methodologies within conventional oil reservoirs.

FIELD OF THE INVENTION

The invention relates to systems, apparatus and methods for integrated recovery and upgrading of heavy oil and oil sand bitumens. The systems, apparatus and methods may enable enhanced recovery of heavy oil from one or more production wells by introducing a hot fluid including a heavy hydrocarbon into one or more wells under conditions to promote hydrocarbon upgrading. The methods may further include introducing hydrogen and a catalyst together with the injection of the hot fluid into the one or more wells to further promote hydrocarbon upgrading reactions. In addition, the invention relates to enhanced oil production methodologies for offshore reservoirs as well as conventional oil reservoirs.

BACKGROUND OF THE INVENTION

Recovery methods for heavy oil or bitumen are often used in reservoirs where the depth of the overburden is too great for surface mining techniques to be used in an economical manner. Being highly viscous, heavy oil and bitumen do not flow as readily as lighter oil. Therefore most bitumen recovery processes involve reducing the viscosity of the bitumen such that the bitumen becomes more mobile and can flow from a reservoir to a production well. Reducing the viscosity of the bitumen can be realized by raising the temperature of the bitumen and/or diluting the bitumen with a solvent.

Steam Assisted Gravity Drainage

Steam Assisted Gravity Drainage (SAGD) is a known technique to extract bitumen from an underground reservoir. In a typical SAGD process, two horizontal wells, (a bottom well and an upper well) are drilled substantially parallel to and overlying one another at different depths. The bottom well is the recovery well and is typically located just above the base of the reservoir. The upper well is the injection well and is located about 5 to 10 meters above the recovery well. Steam is injected into the upper well to form a steam chamber within the formation that, over time, grows predominantly vertically towards the top of the reservoir and downwardly towards the recovery well. The steam raises the temperature of the surrounding bitumen in the reservoir, decreasing the viscosity of the bitumen and allowing the bitumen and condensed steam to flow by gravity into the lower recovery well. The bitumen and condensed steam either flow or are pumped from the recovery well to the surface for separation and further processing. At surface, the separated bitumen is often blended with a diluent such that the bitumen and diluent can be easily transported to a refinery through a pipeline. At the refinery, the diluent is removed and the bitumen is subjected to various processes to separate and upgrade the bitumen into useful products. Principally, bitumen will be subjected to a vacuum distillation process to separate residual, heavy and light components from the bitumen for use in various upgrading processes.

SAGD is generally a very effective methodology of recovering heavy oil or bitumen from the formation to the surface. However, as is known, there are high capital and operating costs associated with SAGD, particularly with respect to the costs of building and operating a steam generation plant and recovery system at the drilling site. In addition, as large amounts of water are required for SAGD, a source of water must be available at the site or water needs to be transported to the site. Large amounts of fuel are also needed for SAGD to raise the temperature of the water to create steam. Further still, the production of high-quality steam from recovered water requires a substantial degree of conditioning at surface to clean the recovered water before reconverting the recovered water back to steam. This conditioning generally requires that the recovered water that is mixed with the produced bitumen must first be separated from the produced bitumen and then subjected to further cleaning to remove any residual contaminants from the water. Upon these cleaning steps, the produced water must then be reheated to produce the high-quality steam for subsequent re-introduction back into the reservoir. As such, the cleaning and re-heating steps require substantial inputs of additional energy both to drive the cleaning processes as well as to re-heat the produced water back to steam. While some energy from the processes can be recovered through heat exchangers, inefficiencies in the processes result in the need for substantial additional energy to be input into the system.

Thus, while SAGD processes are effective, there are substantial environmental costs associated with large-scale SAGD production and specifically that SAGD has a carbon-footprint which is considerably greater than other forms of hydrocarbon production. As a result, there is a need for heavy oil production methodologies that improve the efficiency and particularly the environmental impact of heavy oil production from heavy oil reservoirs.

Vertical Injection/Recovery Wells

Other recovery techniques include the use of one or more vertical wells as a means of applying heat into a reservoir to facilitate hydrocarbon mobility. For example, a single vertical well may be used for cyclic steam stimulation (CSS) which includes successive periods of steam injection, soaking and production. Similarly, two or more vertical wells in proximity to one another may be utilized where, after a start-up period where heat is introduced into the reservoir, one or wells are utilized to apply heat to the reservoir and one or more wells are utilized as production/recovery wells.

VAPEX

Another known in situ recovery process for bitumen or heavy oil is a vapor extraction process (VAPEX), which injects a gaseous solvent (i.e. propane, ethane, butane, etc.) into the upper injection well where it condenses and mixes with the bitumen to reduce the viscosity of the bitumen. The bitumen and dissolved solvent then flow into a lower production well under gravity where they are brought to the surface.

VAPEX is generally considered as being more environmentally friendly and in some circumstances more commercially viable than SAGD, as VAPEX does not require the large amount of water and steam generation that SAGD does. However, the gaseous solvent generally needs to be transported to the production site, and a lengthy start-up interval exists with VAPEX, as it takes longer to grow a vapor chamber with gaseous solvents compared to steam.

In addition, as VAPEX is a non-thermal process conducted at normal reservoir temperatures, it is not efficient in promoting upgrading reactions.

Thus, there are also significant limitations with respect to widespread use of VAPEX.

Catalytic Upgrading

Certain methodologies may incorporate the use of hydrocracking catalysts to assist in the recovery/upgrading process for upgrading and recovering heavy oil and bitumen. However, hydrocracking catalyst particles do not disperse well in the presence of water, as catalyst minerals tend to preferentially migrate to the aqueous phase, and once there, become less available for reactions with hydrocarbons. In addition, water has a limited capacity for carrying dispersed particles through sand formations because of the low viscosity of water. Therefore, while steam and water are not catalyst poisons per se, dispersing catalyst particles in a SAGD chamber dominated by condensate and steam is thought to present significant technical challenges.

Furthermore, at temperatures less than 150° C., the viscosity of bitumen, or vacuum residue, is generally considered to be too high for effective incorporation of catalyst particles and gases such as hydrogen. In other words, in highly viscous bitumen, reaction times are slow due to mass transfer limitations on top of kinetic limitations due to that relatively low energy level.

Enhanced Oil Recovery

In addition to heavy oil reservoirs, other reservoir types including conventional reservoirs having passed peak production and carbonate formations continue to be investigated for new or enhanced oil recovery (EOR) techniques. In conventional reservoirs with decreasing production rates, there continues to be a need for cost-effective methodologies to promote recovery and/or decrease the rates of decline in such reservoirs. In addition, techniques for hydrocarbon production from different carbonate formations continue to be of interest as oil companies seek to exploit these types of reservoirs. As such, new EOR techniques are of interest.

Prior Art

The prior art has many examples of various recovery techniques. For example, recovery techniques that utilize a combination of steam and solvent injections have been proposed. U.S. Patent Publication 2005/0211434 teaches a SAGD recovery process utilizing a higher cost production start-up phase where steam and a heavy hydrocarbon solvent are injected into a reservoir and a lower cost later production phase where a light hydrocarbon solvent is injected into the reservoir to assist in the mobilization of bitumen.

U.S. Pat. No. 4,444,261 teaches a method to improve the sweep efficiency of a steam drive process in the recovery of oil with a vertical production well spaced apart from a vertical injection well. In this technology, steam is injected into the formation via the injection well until steam flooding occurs or there is a steam-swept zone in the upper portion of the formation. Next, a high molecular weight hydrocarbon is injected into the steam-swept zone at a high temperature (500-1000° F.) as a diverting fluid and allowed to cool until it forms an immobile slug in the steam-swept zone. Once the slug is formed, steam injection is resumed and the slug diverts the steam to pass below the slug and below the steam-swept zone, thereby mobilizing the lower portions of oil. In another example, U.S. Pat. No. 6,662,872 teaches a combined steam and vapor extraction process in a SAGD type recovery system.

As upgrading is commonly done to bitumen or heavy oil after it has been recovered, several technologies propose the concept of in situ upgrading, whereby heavy oil's viscosity is permanently reduced and its API gravity is increased as the oil is being produced. For example, U.S. Pat. No. 6,412,557 teaches an in situ process for upgrading bitumen in an underground reservoir in which an upgrading catalyst is immobilized downhole and an in situ combustion process is used to provide heat to facilitate upgrading in a “toe-to-heel” process.

WO 2013/177683 discloses a method for recovery and in situ upgrading of hydrocarbons in a well pair having an injection well and a recovery well within a heavy hydrocarbon reservoir comprising the steps of: introducing a selected quantity of a hot injection fluid including a heavy hydrocarbon fraction into the injection well to promote hydrocarbon recovery and in situ upgrading; and recovering hydrocarbons from the recovery well.

In other examples, U.S. Pat. No. 7,363,973 discloses a method for stimulating heavy oil production in a SAGD operation using solvent vapors in which in situ upgrading may be involved and United States Publication No. 2008/0017372 discloses an in situ process to recover heavy oil and bitumen in a SAGD type recovery system using C3+ (more specifically C3-C10) solvents. Upgrading is described as inherently occurring in view of the solvents contacting the bitumen.

A further example is shown in United States Patent Publication 2006/0175053 that describes a process to improve the extraction of crude oil. This process utilizes an insulated pipe to convey hot fluids to the formation to facilitate extraction. The hot fluids may include paraffins and asphaltenes.

Canadian patent 2,810,022 relates to systems, apparatus and methods for integrated recovery and in-reservoir upgrading of heavy oil and oil sand bitumens. The systems, apparatus and methods enable enhanced recovery of heavy oil in a production well by introducing a hot fluid including a vacuum or atmospheric residue fraction or deasphalted oil into the production well under conditions to promote hydrocarbon upgrading.

Accordingly, while various technologies continue to be developed that advance upon the general methodologies of SAGD and VAPEX, there continues to be a need for improved upgrading method in which a large amount of steam and water are present in the reservoir. As well, improved forms of upgrading techniques are generally needed that are more economical, efficient, and are able to recover a higher proportion of oil.

Further still, there has been a need for improved EOR (Enhanced Oil Recovery) and oil recovery techniques that may be utilized in conventional reservoirs and carbonate formations.

Further still, there has been a need to adapt EOR techniques for offshore operations.

SUMMARY OF THE INVENTION

In accordance with the present disclosure, there is provided systems and methods for in situ upgrading of hydrocarbons within a hydrocarbon formation.

According to a first aspect, there is provided, an apparatus for processing hydrocarbons, the apparatus comprising: an injection well, the injection well being configured to inject fluid into a subterranean reservoir; a recovery well, the recovery well being configured to recover fluid from the subterranean reservoir; and an injection well connector configured to receive heavy hydrocarbon fluid from a mobile surface reservoir and deliver the received heavy hydrocarbon fluid to the injection well to be injected into the subterranean reservoir for processing such that the fluid recovered from the subterranean reservoir via the recovery well has a different composition to the heavy hydrocarbon fluid injected via the injection well.

The recovered fluid may have a different composition by having a different chemical composition (e.g. the hydrocarbons having a different chemical composition). For example, the hydrocarbons may have a different chemical composition by reacting (e.g. in the presence of a catalyst) to form hydrocarbons with shorter carbon chains. The recovered fluid may have a different composition by the addition of chemical compounds obtained from the subterranean reservoir which were not introduced to the subterranean reservoir via the injection well (e.g. native bitumen or other native hydrocarbon deposits).

This method may be particularly applicable to conventional oil production in mature fields (e.g. when the lighter fractions have been removed and heavier fractions remain); and start-up production within heavy oil fields.

Advantages of transporting the heavy hydrocarbon fluid to the injection well include that the use underground reservoir may be used to process non-native heavy hydrocarbons. That is, the underground reservoir becomes part of a ‘processing plant’ in addition to being an oil source.

In addition, by using a mobile reservoir, processing components (e.g. heaters, components for introducing catalysts or other materials into the heavy hydrocarbon) may be distributed between the stationary apparatus components (e.g. an off-shore oil rig) and the mobile surface reservoir (e.g. a transport container). This may allow greater flexibility when designing and using the system. For example, one mobile reservoir may have components configured to initiate heavy hydrocarbon oil well production (e.g. by providing the heat energy to melt and/or upgrade unrecovered native bitumen deposits). After initiation, the well may be self-sustaining. The mobile reservoir may therefore be configured to initiate multiple wells. In another case, the mobile reservoir may be configured to initiate heating of the heavy hydrocarbon fluid en route to the well apparatus.

Other advantages may include that the less storage may be required at the stationary well as the mobile surface reservoir may be used to store products from the well. This is particularly important in off-shore embodiments, where oil-rig storage is limited by the location of the well.

Other advantages include: lower production costs (as the heavy hydrocarbon injection fluid is itself a raw material which can be upgraded into a product using the process); lower emissions; and creation of higher value products.

The subterranean reservoir may be a chamber.

Also, as an injection well and a recovery well are being used, this technology may be applied to existing SAGD wells.

The mobile surface reservoir may form part of an oil tanker ship. The apparatus may form part of an offshore oil rig.

The heavy hydrocarbons may comprise one or more of: bunker fuel and fuel number 6. Fuel number 6 may be known as residual fuel oil (RFO), by the Navy specification of Bunker C, or by the Pacific Specification of PS-400. This is a common fuel source on ships. In this way, the tanker fuel may serve duel purpose: to fuel a ship; and to be used in oil-well production. Furthermore, using the ship's fuel may mitigate the need to add additional reservoirs to existing tankers. Furthermore, such fuels may have more consistent fluid properties. This may allow the catalyst design to be optimized (e.g. adjusting the size and/or shape of catalyst particles to improve delivery).

The ship may comprise: one or more of: a hydrogen plant configured to store or produce hydrogen; a catalyst skid; a heating unit configured to heat fluid for injection (e.g. comprising the heavy hydrocarbons); and a separation unit configured to separate components of the recovered fluid (e.g. a fractional distillation column; a filter for removing catalyst; a filter for removing solid impurities).

The apparatus may comprise a pre-mixer configured to mix the heavy fraction with additional injection fluids and to inject the mixed fluids into the injection well.

The injection well may be configured to inject a portion or all of the heavy residual hydrocarbon fractions at a temperature and/or pressure to promote hydrocarbon upgrading reactions in the subterranean reservoir. The temperature may be one or more of: between 100° C. and 200° C.; between 200° C. and 300° C.; between 300° C. and 400° C.; and between 400° C. and 500° C. The pressure may be 2,000-3500 kPa (˜300-500 psi). In some cases, pressures of up to 2000+ psi may be used.

The apparatus may comprise a recovery well connector configured to enable at least a portion of the recovered hydrocarbons from the recovery well to be delivered to the mobile surface reservoir.

The injection well and recovery well may be operatively connected to a hydrocarbon distillation column for separation of recovered fluids from the recovery well into heavy and light fractions.

The apparatus may comprise a solvent deasphalting separation configured to subject the hydrocarbons recovered from the recovery well to a solvent deasphalting separation process to form a deasphalted oil and an asphaltic pitch.

The apparatus may comprise a heater, the heater configured to heat the heavy hydrocarbons received from the mobile surface reservoir before they are injected into the subterranean reservoir.

According to a further aspect, there is provided a storage container comprising: A mobile surface reservoir for storing heavy hydrocarbons, the storage container configured to enable fluid communication with an injection well such that heavy hydrocarbons contained in the mobile surface reservoir can be injected into a subterranean reservoir via the injection well for processing; and a drive means (e.g. an engine) configured to provide energy for locomotion of the mobile reservoir.

The storage container may comprise a heater, the heater configured to heat the heavy hydrocarbons before they are injected into the subterranean reservoir.

The mobile surface reservoir may be configured to provide at least some of the stored heavy hydrocarbons to the drive means (e.g. engine) as fuel.

the mobile storage container comprises one or more of: a hydrogen source, configured to introduce hydrogen into the heavy hydrocarbons prior to injection into the injection well; a catalyst skid configured to introduce catalyst into the heavy hydrocarbons prior to injection into the injection well; a heater configured to heat the heavy the heavy hydrocarbons prior to injection into the injection well.

The mobile storage container may comprise a fractional distillation column configured to separate fractions of hydrocarbons obtained from the recovery well.

According to a further aspect, there is provided a system, the system comprising the aforementioned apparatus and storage container.

According to a further aspect, there is provided a method for processing hydrocarbons, the method comprising: transporting heavy hydrocarbons from a remote location to an injection well site; injecting the heavy hydrocarbons into a subterranean reservoir via an injection well for processing; and recovering hydrocarbons from the subterranean reservoir via a recovery well, wherein the fluid recovered from the subterranean reservoir via the recovery well has a different composition to the heavy hydrocarbon fluid injected via the injection well.

Transporting heavy hydrocarbons to the wells and reservoir may allow the wells and reservoir to be used as a processing plant for non-native heavy hydrocarbons. In addition, it may allow non-native hydrocarbons to be used to initiate (or re-initiate) production in a reservoir of heavy hydrocarbons (e.g. relatively immobile bitumen deposits).

The heavy hydrocarbons may be transported by a mobile surface reservoir.

The heavy hydrocarbons may be transported by a mobile surface reservoir configured to consume some of the heavy hydrocarbons as a fuel for locomotion.

The heavy hydrocarbons may be transported by pipeline.

The transported heavy hydrocarbons may be injected into the injection well to initiate processing of hydrocarbons already present in the subterranean reservoir.

The method may comprise the steps of: a) introducing a selected quantity of a hot injection fluid including a heavy hydrocarbon fraction into the injection well to promote hydrocarbon recovery and upgrading; and b) recovering hydrocarbons from the recovery well.

The heavy hydrocarbon may be selected from any one of or a combination of shale oil, bitumen, atmospheric residue, vacuum residue, or deasphalted oil.

The hydrocarbons may be recovered from the recovery well and subjected to a separation process wherein heavy and light fractions are separated and wherein the heavy fraction includes a residue fraction.

The residue fraction from the separation process may be mixed with the injection fluid prior to introduction into the injection well.

The method may comprise the step of mixing make-up heavy hydrocarbons with the injection fluid prior to introducing the injection fluid into the injection well and wherein the temperature and pressure of the injection fluid is controlled to promote downhole upgrading reactions.

The injection fluid may include diluent.

The temperature and pressure of the injection fluids may be controlled to promote thermal cracking upgrading reactions.

The temperature of the injection fluid may be controlled to provide a downhole sump temperature of 320±20° C. and/or a downhole residence time of injected fluids is 24-2400 hours.

The temperature and/or pressure of the injection fluids may be controlled such that greater than 30% of residual heavy hydrocarbon of the recovered bitumen is upgraded into lighter fractions.

The temperature and pressure of the injection fluids may be controlled such the recovered hydrocarbons have a viscosity less than 500 cP at 25° C. (or less than 250 cP at 25° C.).

Steam may be injected into the horizontal well pair prior to the introduction of the hot injection fluid comprising a heavy hydrocarbon to initiate connection between the injector well and the recovery well and formation of a downhole reaction chamber.

Steam may be progressively replaced with a heavy hydrocarbon fluid (e.g. selected from any one of or a combination of heavy oil, shale oil, bitumen, atmospheric residue, vacuum residue, or deasphalted oil). This may allow initation of production in a heavy hydrocarbon reservoir (e.g. containing relatively immobile bitumen deposits).

The method may include the step of mixing a catalyst into the injection fluid prior to introducing the injection fluid into the injection well.

The method further may comprise the step of mixing hydrogen into the injection fluid prior to introducing the injection fluid into the injection well.

The temperatures and pressures of the injection fluid may be controlled to promote any one of or a combination of hydrotreating, hydrocracking or steam-cracking reactions.

The hydrogen may be mixed with the injection fluid to provide excess hydrogen for the hydrotreating and hydrotreating reactions.

The hydrogen may be injected along the length of the injection well.

Approximately 1/3 of the hydrogen may be mixed with the injection fluid at surface and the remaining approximately 2/3 may be injected to the reservoir along the horizontal length of the recovery well.

The hydrogen may be injected from the recovery well via at least one liner operatively configured to the recovery well.

The catalyst may be any one of or a combination of nano-catalysts or ultradispersed catalyst wherein the nano-catalyst may have particles with dimensions less than 1 micron and/or less than 120 nm. The nano-catalyst may be suspended in a hydrocarbon carrier (e.g. the heavy hydrocarbon).

A plurality of adjacent interconnecting well pairs may be configured to a single well pad wherein one of the interconnecting well pairs is an upgrading well pair and wherein heavy hydrocarbon fluids recovered from each well is mixed with the injection fluid of the upgrading well pair.

The heavy hydrocarbon fluids may include any one of or a combination of heavy oil, shale oil, bitumen, atmospheric residue, vacuum residue, or deasphalted oil

The injection well and recovery well may have vertically overlapping horizontal sections and the injection well is the lower of the injection well and the recovery well.

The injection well and recovery well may have vertically overlapping horizontal sections and the injection well is the upper of the injection well and the recovery well.

The method may comprise the steps of: a) drilling an injection well and recovery well into the heavy hydrocarbon formation; b) creating a hydrocarbon mobilization chamber within the heavy hydrocarbon formation by introducing a hot fluid into the injection well so as to promote hydrocarbon mobility to the recovery well; c) recovering heavy hydrocarbons from the recovery well to the surface; d) subjecting the recovered hydrocarbons from step c) to a separation process to form lighter hydrocarbon fractions and heavy residual hydrocarbon fractions; e) introducing a portion or all of the heavy residual hydrocarbon fractions at a temperature and pressure to promote hydrocarbon upgrading reactions in the hydrocarbon mobilization chamber; and, f) recovering co-mingled and upgraded hydrocarbons from the recovery well.

A portion of the heavy residual fraction from the separation may be used as a fuel to produce heat to heat the injection fluids for upgrading reactions.

The method may comprise the step of using a portion of the lighter hydrocarbons to additional separation processes for commercialization.

Introducing a portion or all of the heavy residual hydrocarbon fractions at a temperature and pressure to promote hydrocarbon upgrading reactions in the hydrocarbon mobilization chamber may include introducing a catalyst into the injection well to promote catalytic upgrading within the injection well and the hydrocarbon mobilization chamber and/or introducing hydrogen into the injection well to promote upgrading reactions within the hydrocarbon mobilization chamber.

In yet another aspect, there is provided a system for recovery and in situ upgrading of heavy hydrocarbons within a heavy hydrocarbon formation comprising: an injection well; a recovery well; the injection well and recovery well operatively connected to a hydrocarbon distillation column for separation of recovered fluids from the recovery well into heavy and light fractions; and, a mixing and hot fluid injection system operatively connected to the distillation column for recovering heavy fractions from the distillation column and for mixing the heavy fraction with additional injection fluids for injection into the injection well;

The system may comprise a gas/liquid separation system operatively connected to the recovery well for separating gas and liquids recovered from the recovery well and for delivering separated liquids to the distillation column and/or a catalyst injection system operatively connected to the mixing and hot fluid injection system for introducing catalyst to the mixing and hot fluid injection system and/or a hydrogen injection system operatively connected to the mixing and hot fluid injection system for introducing hydrogen to the mixing and hot fluid injection system and/or a diluent injection system operatively connected to the mixing and hot fluid injection system for introducing diluent to the mixing and hot fluid injection system and/or at least one additional injection and recovery well operatively connected to the distillation column for introducing additional heavy hydrocarbons from the at least one additional recovery well to the distillation column.

In yet a further aspect, there is provided a method of upgrading heavy hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation comprising the steps of: a) drilling an injection well and recovery well into the heavy hydrocarbon formation; b) creating a hydrocarbon mobilization chamber within the heavy hydrocarbon formation by introducing a hot fluid into the injection well so as to promote hydrocarbon mobility to the recovery well; c) recovering heavy hydrocarbons from the recovery well to the surface; d) subjecting the recovered hydrocarbons from step c) to a solvent deasphalting separation process to form a deasphalted oil and an asphaltic pitch; e) introducing deasphalted oil from step d) into the injection well at a temperature and pressure to promote hydrocarbon upgrading reactions in the hydrocarbon mobilization chamber; and, f) recovering co-mingled and upgraded hydrocarbons from the recovery well.

A portion of the asphaltic pitch may be used as a fuel to produce heat to heat the injection fluids for upgrading reactions.

The method may comprise using a portion of the lighter hydrocarbons to additional separation processes for commercialization.

In yet another aspect, there is provided a system for recovery and in situ upgrading of heavy hydrocarbons within a heavy hydrocarbon formation comprising: an injection well; a recovery well; wherein the injection well and recovery well operatively connected to a solvent deasphalting system for recovering a deasphalted oil fraction for mixing with additional injection fluids for injection into the injection well.

In yet another aspect, there is provided a method of upgrading heavy hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation comprising the steps of: a) drilling a well into the heavy hydrocarbon formation; b) introducing heat into the well to create a hydrocarbon mobilization chamber within the heavy hydrocarbon formation so as to promote hydrocarbon mobility within the well; c) recovering heavy hydrocarbons from the recovery well to the surface and initially storing the heavy hydrocarbons in a heated tank; d) introducing heavy hydrocarbons from the heated tank into the well at a temperature and pressure to promote hydrocarbon upgrading reactions in the hydrocarbon mobilization chamber; e) sealing and maintaining pressure in the well for a time sufficient to promote hydrocarbon upgrading reactions; and, f) after a sufficient time, releasing the well pressure and recovering upgraded hydrocarbons from the well.

The method may include introducing catalyst into the well during step d); and/or introducing hydrogen into the well when heavy hydrocarbons are introduced into the well from the heated tank.

In another aspect, the there is provided a method for recovery and in situ upgrading of hydrocarbons in a well pair having an injection well and a recovery well within a heavy hydrocarbon reservoir comprising the steps of: (a) introducing a selected quantity of a hot injection fluid including a heavy hydrocarbon fraction selected from any one of or a combination of shale oil, bitumen, atmospheric residue, vacuum residue, or deasphalted oil into the injection well to promote hydrocarbon recovery and in situ upgrading; (b) recovering hydrocarbons from the recovery well; (c) subjecting the hydrocarbons recovered from the recovery well to a separation process wherein heavy and light fractions are separated to produce any one of or a combination of shale oil, bitumen, atmospheric residue, vacuum residue and a deasphalted oil fraction; and, (d) re-introducing any one of the shale oil, bitumen, atmospheric residue, vacuum residue or deasphalted oil fraction into the well as a hot injection fluid under temperature and pressure conditions to promote upgrading and repeating steps (a) to (d).

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments are described with reference to the accompanying figures in which:

FIGS. 1A and 1B are schematic diagrams of an offshore embodiment.

FIG. 2 is a schematic diagram of a residue assisted in situ upgrading (RAISUP) process in accordance with a further embodiment.

FIG. 3 is a schematic diagram of a residue assisted in situ catalytic upgrading (RAISCUP) process in accordance with a third embodiment.

FIG. 3A is a schematic plan view of a RAISUP process utilizing multiple well pairs.

FIG. 3B is a schematic cross view of various RAISUP processes using one or more vertical wells as injection/production wells.

FIG. 4 is a schematic diagram of a recovery chamber in accordance with one embodiment.

FIG. 5 is a schematic diagram of a typical temperature gradient in an upgrading well pair and recovery chamber in accordance with one embodiment.

FIG. 6 is a schematic diagram of surface facilities for an upgrading well pair in accordance with another embodiment.

FIG. 6A is a side view schematic of a mobile surface reservoir connected to an off-shore oil rig.

FIG. 7 is a schematic diagram of surface facilities for an upgrading well pair in accordance with another embodiment utilizing deasphalted oil.

FIG. 8 is a schematic diagram of the upgrading zones according to one embodiment.

FIG. 9 is a schematic diagram of another embodiment using a huff and puff methodology.

DETAILED DESCRIPTION OF THE INVENTION Overview

In accordance with the present disclosure and with reference to the figures, systems, apparatus and methods for upgrading of hydrocarbons in hydrocarbon recovery operations are described. In particular, the methods enable upgrading of heavy oils and bitumen within a production well bore and formation chamber using hot injection fluids. In particular, embodiments are described in which oil transported to the site by a mobile surface reservoir is upgraded in the well and/or reservoir. In a further embodiment, the hot injection fluid includes a residue fraction. In a further embodiment, the injection fluid includes deasphalted oil. In each case the hot injection fluid comprises fluid delivered by a mobile surface reservoir. In some embodiments, hydrogen gas and a catalyst may be injected together with the hot injection fluid to promote upgrading and recovery of the heavy oils and bitumen. It will be appreciated that the upgrading may comprise upgrading of native hydrocarbons (i.e. hydrocarbons originating from the well); and/or upgrading of introduced (or non-native) hydrocarbons (e.g. hydrocarbons transported to the well by the mobile surface reservoir).

In accordance with the present disclosure and in the context of this description, the following general definitions are provided for the terms used herein. Extra heavy hydrocarbons are generally defined as those hydrocarbon fractions that are distilled above temperatures of 500° C. (atmospheric pressure) or have an API gravity less than 10 (greater than 1000 kg/m³). Heavy hydrocarbons are distilled between temperatures of 350° C. and 500° C. or have an API gravity between 10 and 22.3 (920 to 1000 kg/m³). Medium hydrocarbons are distilled between temperatures of 200° C. and 350° C. and are generally defined as having an API gravity between 22.3 API and 31.1 API (870 to 920 kg/m³). Light hydrocarbons are defined as having an API gravity higher than 31.1 API (less than 870 kg/m³) and are distilled below 200° C.

A residue fraction is the fraction that distills at temperatures higher than 540° C. A deasphalted oil (DAO) fraction is a crude fraction produced in a deasphalting unit (DAU) that separates asphalt from bitumen.

Offshore Upgrading

In a first embodiment, as shown in FIGS. 1A and 1B, there is provided a system for upgrading native and/or non-native heavy hydrocarbons within a well and/or reservoir. In particular, the embodiment of FIG. 1 comprises an apparatus 110 for processing hydrocarbons, the apparatus comprising: an injection well 111, the injection well being configured to inject fluid into a subterranean reservoir 113; a recovery well 112, the recovery well being configured to recover fluid from the subterranean reservoir; and an injection well connector 115 configured to receive heavy hydrocarbon fluid 131 from a mobile surface reservoir 121 and deliver the received heavy hydrocarbon fluid 131 to the injection well 111 to be injected into the subterranean reservoir 113 for processing such that the fluid recovered from the subterranean reservoir via the recovery well 112 has a different composition to the heavy hydrocarbon fluid injected via the injection well.

In this case, the mobile surface reservoir forms part of an oil tanker 120. The injection and recovery wells form part of an offshore oil-rig apparatus 110.

In this case, the heavy hydrocarbons 131 comprise one or more of: bunker fuel including various fuels such as fuels 2-6 but preferably fuel number 5 or fuel number 6 or combinations thereof. In this case, the mobile surface reservoir is configured to provide at least some of the stored heavy hydrocarbons to the oil tanker engine 122 as fuel. In this way, the need for multiple (or additional) tanks on the oil tanker (e.g. one for the heavy hydrocarbons and one for fuel) may be mitigated.

Bunker fuel may comprise number 5 fuel oil, which may be obtained from the heavy gas oil cut, or it may be a blend of residual oil with enough number 2 oil to adjust viscosity until it can be pumped without preheating. Bunker fuel may comprise number 6 fuel oil, which is a high-viscosity residual oil. Residual oil is the material remaining after the useful cuts of crude oil have boiled off. The residue may contain various impurities including water (e.g. up to 2%) and mineral soil (e.g. up to 0.5%). Bunker fuel may have an API gravity of between around 12 and 15. Bunker fuel may comprise aromatic components. Aromatic components may make up between 50-60 wt % (e.g. around 55%) of the heavy hydrocarbons in bunker fuel.

In this case, the offshore oil-rig apparatus is used to upgrade and process the bunker fuel into lighter fractions. Initially, the heavy hydrocarbons are heated to a temperature of around 330-380° C. with a heater. In this case, the heater 124 is located on the oil tanker although it will be appreciated that the heater may be located on the oil-rig apparatus. The heating reduces the viscosity of the heavy hydrocarbons which allows them to be pumped more easily from the mobile surface reservoir ship. The heavy hydrocarbons are then mixed with a catalyst to promote cracking of the long-chain hydrocarbons. In this case, the catalyst is introduced on the oil-tanker using a catalyst skid 125, although it will be appreciated that the catalyst may be introduced on the oil-rig apparatus. A catalyst skid 125 is preferably a small catalyst manufacturing plant enabling the production of, for example, mono, bi and/or tri-metallic nano-catalysts suspended in a heavy oil medium.

The heated heavy hydrocarbons and catalyst are received from the mobile surface reservoir via an injection pipe connector 115, and then injected into the subterranean reservoir via the injection well. Additional hydrogen may also be introduced into the injected mixture using hydrogen source 125. In this case, the hydrogen source is located on the oil tanker 120, although it will be appreciated that the catalyst skid may be introduced on the oil-rig apparatus 110.

In this case, because the heavy hydrocarbons are heated in the presence of the catalyst, upgrading may already be initiated in the injection well before the heavy-hydrocarbon/catalyst mixture reaches the subterranean reservoir. These upgrading reactions may be exothermic, and so serve to heat the heavy hydrocarbon mixture as it moves towards the subterranean well. Bunker fuel upgrading reactions may be particularly exothermic because of the high proportion of aromatic compounds in bunker fuel.

As these reactions are a heat source, a lower temperature may be required at the surface to ensure that the appropriate down-well temperature is maintained. In contrast, if steam is used, a higher temperature may be required at the surface to compensate for heat losses during transit via the injection well. Another advantage of the upgrading reactions occurring in the injection well is that, when the hot injection fluid reaches the subterranean reservoir, the hot injection fluid may comprise a greater proportion of shorter-chain hydrocarbons. These shorter-chain hydrocarbons may act as a diluent for the hot injection fluid and for native heavy hydrocarbon deposits (e.g. bitumen) in the subterranean reservoir. Therefore, the hot injection fluid hydrocarbons may help dissolve and thereby help mobilise native heavy hydrocarbon deposits. In contrast, when using steam (e.g. in a conventional SAGD process), it is mainly the temperature of the injection fluid that mobilises the native deposits as hydrocarbons are generally insoluble in water.

In the subterranean reservoir, the increased pressure may facilitate further upgrading reactions. In addition, the heat from the introduced non-native heavy hydrocarbons may melt native heavy hydrocarbon reserves (e.g. comprising bitumen). When these native hydrocarbons come in contact with the introduced catalyst (and/or hydrogen) in situ upgrading of the native heavy hydrocarbons may take place facilitating their removal via the recovery well.

The recovery well is configured to enable extraction of any sufficiently mobile material from the subterranean reservoir. The extracted material may comprise one or more of: upgraded non-native hydrocarbons; upgraded native hydrocarbons; catalyst material; mobile non-upgraded native hydrocarbons; and mobile non-upgraded non-native hydrocarbons. Mobile heavy hydrocarbons may include suspended particles of solid hydrocarbon and/or hydrocarbons dissolved in a diluent.

In this case, the oil-rig apparatus comprises a fractional distillation column 116 to separate the various grades of hydrocarbon obtained from the recovery well. In other embodiments, the fractional distillation column may be located on (e.g. form part of) the oil tanker. The mixtures recovered from the recovery well may be subjected to dewatering processes within a dewatering system 118 as required.

In this case, the oil-rig apparatus 110 is configured to return the bunker-fuel grade fraction to the mobile surface reservoir via a recovery connector 114. This reduces the need for storage on the oil-rig for heavy oil fractions. It will be appreciated that the oil tanker ship may have one or more separate reservoirs 123 (i.e. separate from the heavy hydrocarbon mobile surface reservoir 121) to facilitate transport away from the oil-rig apparatus of any produced lighter oil fractions.

The apparatus may comprise a means for removing the catalyst (e.g. a filter) from the material extracted from the recovery well prior to being processed in the fractional distillation column; although in most operations, the catalyst will remain within the heavier fractions recovered from the distillation column. Recovered catalyst may be mixed in with further heavy hydrocarbons (e.g. from the mobile surface reservoir and/or heavy distilled fractions) and reintroduced into the subterranean reservoir 113 via the injection well 111. That is, heavy fractions received from the recovery well may be re-injected into well at high temperature and pressure in combination with catalyst and hydrogen to promote in situ upgrading reactions. This cycle may be repeated a number of times.

By way of example, when a steady state is achieved, a well producing 6000 bpd (barrels per day) may use 1000-1500 bpd of bunker fuel (e.g. Bunker C). That is, a ratio of 6:1 to 4:1 (produced oil: injection fluids) would be typical.

The transport of and processing of heavy hydrocarbons may also be facilitated in a similar way in an on-shore embodiment by, for example, a train or truck comprising a mobile surface reservoir. For example, the train or truck mobile surface reservoir may be used to transport heavy hydrocarbon, such as vacuum residue (which is often a component of bunker C fuel) or bunker C, from a refinery to an on-shore upgrading well site. In a similar manner to that described above, the transported heavy hydrocarbon is injected (possibly after bunker diluent recovery) at the well site at high temperature and pressure. Hydrogen and catalyst may also be included in the fluid injected into the injection well.

As with the previous case, the recovered hydrocarbons may be processed by separating them into their various fractions. Heavier fractions may be re-injected into the well for further upgrading or blended with the bunker diluent for transport away from the site.

Residue Assisted In situ Upgrading (RAISUP)

In a further embodiment, as shown in FIG. 2, there is provided a system for Residue Assisted In situ Upgrading (RAISUP) in an in situ upgrading chamber 12 having an upgrading well pair 13. In accordance with this embodiment, one of the wells of the upgrading well pair is an injection well 16 and the other well is a recovery well 18. Well pairs may be horizontal, vertical or inclined and may comprise combinations of such wells as shown in FIG. 3 b. For the purposes of description, a horizontal well pair is described although it is understood that other combinations of well pairs may be utilized including a single well also shown in FIG. 3 b. Initially, hot fluid or steam is injected into the injection well, causing a chamber 12 to grow at and around the injection point 16 a. The recovery well 18 serves to collect the recovered fluids, from which the recovered fluids flow or are pumped to the surface. At the surface, the recovered fluids enter an atmospheric and/or vacuum distillation column 20 where the heavy oil is separated into fractions by weight, leaving at the bottom of the distillation column a heavy vacuum or atmospheric residue fraction 20 a (the “residue fraction”), and at higher levels of the column, lighter oil fractions 20 b, recovered gases 20 c and recovered diluent 20 d (if utilized).

In accordance with the present disclosure, the hot fluids injected into the injection well include the residue fraction 20 a transported to the site by a mobile surface reservoir (e.g. an oil tanker ship, a train or a truck). The residue fraction may comprise a fraction from a distillation column, additional bitumen 20 e from another source and/or diluent 20 f and/or other hot fluids. Importantly, injecting the residue fraction promotes in situ thermal cracking/upgrading reactions to occur within the formation. In addition, the injection of a residue fraction affects the overall efficiency of upgrading reactions as the heavy oil fractions are most reactive to heat driven upgrading reactions. It will be appreciated that in addition to the in situ thermal cracking/upgrading reactions, the present embodiment also facilitates thermal cracking/upgrading reactions within the heavy hydrocarbons which have been transported to the site by the mobile surface reservoir. That is, oil processing facilitated by one or more embodiments may include cracking the heavy hydrocarbons themselves (i.e. delivered by the mobile surface reservoir) and/or inducing further oil production from the subterranean reservoir.

Importantly, the injection of the hot residue fraction into the injection well is also an effective source of introducing heat into the chamber 12.

In this case, the mobile surface reservoir 10 may be used as a temporary storage container for the hot residue fraction. In this way, dedicated storage for this fraction may not be required to be incorporated into the stationary well equipment.

In this case, the mobile surface reservoir may form part of a train (e.g. comprising one or more tank cars). A tank car (such as a DOT-111 tank car or a CTC-111A) may have a capacity of between 80,000 and 150,000 liters (500-950 barrels of oil).

In the present embodiment, the residue may be heated in the mobile surface reservoir 10 and injected into the injection well at around 350±20° C. which ideally provides an average reservoir sump temperature of 320±20° C. Importantly, as the injected hot residue temperature is thus generally higher than that of steam, the hot residue will cause the chamber to more rapidly expand during start-up operations and/or more rapidly maintain a steady state size.

In addition, a sump temperature of around 320±20° C. promotes thermal upgrading of the bitumen in the injection well and oil reservoir by increasing the temperature of the bitumen to a temperature at which upgrading reactions can occur (e.g. thermal cracking), as well as decreasing the viscosity of the bitumen to improve the overall mobility of the bitumen in the reservoir.

Under steady state conditions, the residence time for the injected residue may vary between approximately 24-2400 (normal upper limit about 500) hours depending on the size of the chamber and the permeability of the porous media as understood by those skilled in the art. Recovered bitumen may be partially but significantly upgraded to produce a number of heavy oil products having a typical viscosity less than 300 cPoises @ 60° F. and 14-15 API gravity as compared to a typical API gravity of 8-10 for recovered bitumen at similar conditions. Under typical conditions, a residence time of 24-48 hours will result in more than 30% of the recovered bitumen being upgraded.

The mass balance of the system may be described by a representative description of a producing well. For example, after breakthrough, a well may be producing 300 bpd at steady state. Thus, 300 bpd will be introduced into a distillation column for separation of heavy hydrocarbons and market fractions. Assuming that 50% of the recovered 300 bpd is a market fraction, 150 bpd from the column will be reinjected into the well. The requirement for additional heavy hydrocarbons will depend on a number of factors including the reservoir pressure and temperature, the ability to maintain the reservoir pressure and temperature with the heavy hydrocarbons from the column as well as the volume of heavy hydrocarbons being recovered from the column. That is, to the extent that 150 bpd from the column is capable of maintaining reservoir temperature and pressure, no additional heavy hydrocarbons may be required. However, if reservoir temperature and pressure is dropping with the injection of only 150 bpd, additional heavy hydrocarbons may be required. The amount of additional heavy hydrocarbons will typically be less than or equal to the volume of the market fraction but may be more in some circumstances.

A further advantage of hot residue injection is that the recovered oil is at a higher temperature and contains much less water than with steam injection. Accordingly, injecting hot residue can effectively eliminate the injection of water into the reservoir, such that the only water in the reservoir will be connate water. As a result, water treatment and/or water disposal costs may be eliminated or substantially reduced.

That is, in this embodiment, even during start-up, hot residue (e.g. bitumen, Deasphalted oil, Vacuum Gas oil etc. which has been transported to the well site using the mobile surface reservoir) can be injected into the injection well to begin growing the chamber during the start-up phases. At a later stage, the transported hot residue may be progressively replaced with hot residue obtained from the well itself (e.g. native heavy hydrocarbons) over a time period. Thus, even during start-up, water treatment and recovery may be minimized. Using heated oil from a mobile surface reservoir and enabling recirculation of hot oil within the wells may allow multiple wells to achieve connectivity.

It should be noted that the use of hot residue to grow the chamber generally results in greater horizontal expansion of the chamber instead of vertical expansion due to the generally greater horizontal permeability of heavy oil formations in comparison to vertical permeability. Importantly, a more laterally expanded chamber may result in more complete recovery than the typical vertical chamber of SAGD processes, as greater horizontal expansion will result in a greater overall volume of the recovery chamber. Because the shape of the subterranean reservoir may be dependent on the process used to create the subterranean reservoir, it may be advantageous to use heavy hydrocarbons to create the subterranean reservoir rather than steam (e.g. in a conventional SAGD process) in order to control the shape of the subterranean reservoir. Creating the well using heavy hydrocarbons may be facilitated using a mobile surface reservoir to transport the heavy hydrocarbons to the well apparatus.

It will be appreciated that such a system may be used for offshore wells, with the mobile surface reservoir comprising, for example, an oil tanker ship. An oil tanker ship mobile surface reservoir may have a capacity of 2,000,000 barrels (320,000 m³). A general purpose tanker may have a deadweight tonnage of 10,000-24,999; a medium range tanker may have a deadweight tonnage of 25,000-44,999; an LR1 (Large Range 1) may have a deadweight tonnage of 45,000-79,999; an LR2 (Large Range 2) may have a deadweight tonnage of 80,000-159,999; a VLCC (Very Large Crude Carrier) may have a deadweight tonnage of 160,000-319,999; a ULCC (Ultra Large Crude Carrier) may have a deadweight tonnage of 320,000-549,999.

Residue Assisted In-situ Catalytic Upgrading (RAISCUP) Process

In accordance with another aspect of the present disclosure and with reference to FIGS. 2-8, systems and methods for Residue Assisted In situ Catalytic Upgrading (RAISCUP) in a hydrocarbon recovery operation are described. In particular, these methods enable catalyst-assisted upgrading of heavy oils and bitumen within a production well bore and formation chamber having a single well or well pair.

As shown in FIG. 3, in this embodiment, catalyst 30 and hydrogen 28 are injected into the injection well to further promote upgrading reactions including hydrotreating and hydrocracking reactions in addition to thermocracking reactions. As in FIG. 2, the system includes an upgrading well pair 13 consisting of an injection well 16 and a recovery well 18 in which the injection well serves as a point of entry for injected fluids 38 and the recovery well collects recovered fluids 44 which flow or are pumped to the surface. As explained in greater detail below, either well from the well pair may serve as the injection well. However, for the purposes of illustration in situations with one or more horizontal well pairs, FIGS. 2-5 illustrate the top well as the injection well 16 and the bottom well as the recovery well 18.

In one embodiment, the system is designed for use with a plurality of horizontal well pairs served by one well pad 50 in which one of the adjacent well pairs (50 a, b, c, d) is used for upgrading reactions (FIG. 3A). For example, bitumen recovered in adjacent well pairs (50 b, c, d) may be upgraded in well pair 50 a in which all the bitumen recovered from the adjacent well pairs (approximately 500 to 1000 barrels per day per well pair) could be upgraded in one upgrading well pair for efficiency reasons.

In this embodiment as shown in FIG. 3, the injected fluids 38 preferably comprise hydrogen 28, heavy hydrocarbons (e.g. residue fraction 20 a and/or other bitumen 20 e), diluent 20 f (optional) and catalyst 30. As noted above, at least some of the heavy hydrocarbons are provided via a mobile surface reservoir (e.g. an oil tanker).

The mobile surface reservoir maybe configured to mix the heavy hydrocarbons with 10 to 15% diluent (condensate) 20 f (FIG. 2) to assist in the transport and mobility of bitumen into the well during start-up and explained in greater detail below. Once the upgrading well pair is undergoing steady upgrading operation the diluent can be removed for recycling and no more bitumen is injected to the reservoir and instead the residual fraction from the distillation column is used.

During steady-state operation, incoming bitumen 20 e and diluent 20 f will be blended with hot residue 20 a along with recovered and makeup hydrogen 28 and makeup catalyst 30 together with recovered hydrogen and gases 32 prior to injection into the upgrading well pair. Recovered fluids 44 are subjected to appropriate gas/fluid separation to recover some hydrogen for re-injection.

The catalyst is preferably a nano-catalyst or ultradispersed catalyst, as described in U.S. Pat. No. 7,897,537 incorporated herein by reference. The catalyst may have a composition of the general formula: B_(x)M_(y)S_([(1.1 to 4.6)y+(0.5 to 4)x]) where B is a group VIIIB non-noble metal and M is a group VI B metal and 0.05≤y/x≤15 and wherein the catalyst composition is an ultradispersed suspension in a hydrocarbon solvent with a median particle diameter from 30 nm to 6000 nm. The composition may be configured such that 0.2≤y/x≤6. The composition may be configured such that y/x=3. The Group VI B metals include chromium, molybdenum, tungsten and mixtures thereof. The Group VIII B non-noble metals include, iron, cobalt, nickel or mixtures thereof. Preferably, the combinations of the metals are iron, cobalt, nickel or mixtures thereof with chromium, molybdenum, tungsten or mixtures thereof. The suitable Group VI B metals which are at least partly in the solid state before contacting the protic medium, comprise polyanions such as molybdates, tungstates, chromates, dichromate; or oxides such as molybdenum oxides, tungsten oxides, chromium oxides. The suitable Group VIII B non-noble metals comprise water-soluble metal salts such as acetate, carbonate, chloride, nitrate, actylacetonate, citrate and oxalate. The ultradispersed suspension may have a median particle diameter between 60 nm to 2500 nm.

The catalyst may be produced on site by transporting the catalyst precursors to the site, or a pre-manufactured catalyst may be transported to the site. The hydrogen may be initially shipped to the site and produced with small units (hydrogen generators) as the hydrogen pressure and its consumption is much lower than typically needed in conventional surface upgrading, and after production has started, as noted above, the unreacted hydrogen dissolved in the produced oil coming to the surface can be recovered from the distillation process and gas/fluid separation 32.

In the case where the average residence time of the injected fluids 38 in the upgrading zone is more than 150 hours, upwards of 45% of the heavy oil fractions can be converted to upgraded oil with 14-16° API. After a sufficient residence time, the recovered fluids 44 from the recovery well 18 are introduced into the column 20 for separation. Lighter fraction oil products 20 b are removed and residual catalyst, residue fraction separated from the vacuum/atmospheric residue to recover and recycle the catalyst particles, resulting in upgraded oil 32 with more than 20° API. The recovered fluids 44 are composed of excess hydrogen, upgraded 14-16° API oil, unconverted bitumen and atmospheric/vacuum residue, other produced gases (CH₄, H₂S and H₂O from connate water), and catalyst not retained in the upgrading zone.

At the surface, excess hydrogen and other gases 32 are separated and recycled. The remaining recovered liquids 44 are sent to the distillation column 20 for vacuum/atmospheric residue and catalyst recovery. Generally, it is preferred that the upgrading zone 40 retains a proportion of catalyst particles because it minimizes the scope of catalyst recovery and reduces the amount of on-going catalyst injection that occurs, thereby reducing catalyst costs. In the distillation column, diluent 24 may be recovered and recycled to adjacent or other well pairs if desired. Upgraded oil 34 derived from the residue is sent to market. Recovered catalyst and the residue fraction 20 a are returned to the upgrading well pair. It will be appreciated that heavy recovered fractions may be returned to the mobile surface reservoir.

Catalyst will generally be retained in the reservoir until it starts to rise in the recovered fluids and will reach a plateau amount at a concentration lower than the amount being injected. A steady concentration of catalyst will come up to the surface. As the catalyst is heavier (in terms of density) than the heaviest upcoming oil molecules, it will generally remain in the residue during distillation. Entrainment in particles and/or carry-over is unlikely as the distillation columns are generally designed to prevent entrainment and carry-over. However, filters will normally be incorporated downstream of the bottom of the distillation column to retain any large particle in the residue (either sand or agglomerated particles including catalyst that may come up to the surface). Moreover, it is also noted that the heaviest distillates from a vacuum distillation column will generally carry no particles of lighter density carbonaceous material (micro coke particles) that could eventually be entrained by distillation, which indicates that these columns are effective for particle separation. Moreover, the catalyst concentration at injection will be low (less than 1000 ppm in the residue (<0.1% by weight) and it will be substantially lower in the produced fluids; a typical norm BWS (bottom water and sediments) specifies 0.5% wt for example.

That is, the catalyst particles are effectively separated at the lowest cost from the upgraded produced oil by remaining in the fraction that is recycled to the reservoir. As a result, the produced lighter oil from the distillation column is generally ready to be transported without containing catalyst particles. In addition, re-injected residue fraction will ultimately be fully converted to lighter fractions and the un-upgradable heaviest fractions will be eventually left back in the reservoir if desired.

Furthermore, bitumen contains naphthenic molecules that may undergo repeated cycles of dehydrogenation and hydrogenation in the upgrading zone 40. Therefore, naphthenic molecules may contribute to the redistribution of hydrogen to larger residue molecules, thereby improving residue conversion efficiency as per the following example chemical equation:

Upgrading and Recovery Chamber

The RAISCUP process also results in recovery of bitumen from the formation hosting the upgrading well pair. As shown in FIGS. 2, 3 and 4, the upgrading/recovery chamber 12 generally includes two zones namely the upgrading zone 40 and the recovery zone 42. The upgrading zone is generally the interwell zone 50 through which the injected fluids flow. It is generally maintained at around 350° C. by the heat of the upgrading reaction.

Above the upgrading zone is the recovery zone. As shown in FIG. 4, heat from the upgrading zone 40 is transferred by conduction and warms surrounding bitumen, reducing its viscosity. Very hot hydrocarbon vapors, produced by the upgrading reaction, and augmented by diluent and distillate recycling from the surface if needed, rise into the recovery zone, transferring additional heat by convection. The hot hydrocarbon vapors dissolve into the formation bitumen and further reduce the viscosity of the formation bitumen. Gravity drainage, supported by the displacement of rising gases 52, including hydrogen, hydrocarbon vapors, water vapor, and other gases, mobilizes and recovers bitumen 54 through the recovery well. This process results in the upgrading of bitumen produced by adjacent well pairs as well as recovery and upgrading of bitumen from the upgrading well pair. In the upgrading well pair, preferably no steam is injected but hydrogen can be. Hence, bitumen is recovered through vapor extraction, gravity drainage and gas displacement along with a much lower contribution to recovery (with respect to SAGD) of steam from connate water.

Start Up

To start the RAISUP or RAISCUP processes, in one embodiment two horizontal wells are drilled, vertically spaced approximately 5 m apart, with the length of the horizontal section subject to optimization. A longer length will generally increase the daily rate of bitumen and residue upgrading. At a temperature of 350° C., up to 1000 barrels (˜160 m³) per day per 100 m of well length comprising 50% bitumen and 50% residue can be injected (e.g. at least partially from a mobile surface reservoir). For example, 5000 barrels per day of bitumen could flow through a 1000 m long upgrading well pair, providing enough capacity to upgrade bitumen produced by 3 to 4 adjacent SAGD well pairs each producing 500 to 1000 barrels per day, as well as recycled residue fraction. In this way, this embodiment facilitates upgrading native and non-native heavy hydrocarbons.

As noted, the wells are optionally/preferably preheated by the circulation of hot oil inside the wells. As is known, during steam pre-heating it will typically take approximately 4 months to establish hot fluids communication between the wells wherein the interwell region 50 should reach a temperature of approximately 160° C. A low viscosity oil (vacuum gas oil, VGO) at about 300° C. can be recirculated inside the wells to establish hot fluids communication between the wells wherein the interwell region 50 should reach a temperature of approximately 160° C. A hot heavy hydrocarbon fluid (e.g. from a mobile surface reservoir) may be used to establish hot fluid communication between the wells. As noted above, this procedure can eliminate the use of steam and water treatment needs. The shape of the interconnected subterranean reservoir regions may be controlled by controlling the type of material used to create the subterranean reservoir.

After the preheat phase, low viscosity oil at 350° C. (i.e. atmospheric residue or VGO used during preheating) is injected and circulated using the top well for injection, and the bottom well for recovery. The injected oil is saturated with hydrogen and nano-catalysts to protect it from coking. When the temperature of the interwell region reaches approximately 250° C., bitumen (or other heavy hydrocarbon) is injected in place of low viscosity oil. The purpose of this phase is to heat the interwell zone to the desired upgrading temperature of 350° C.

At the same time, the volume of hydrogen in the injection fluid is gradually increased until excess hydrogen conditions required for effective upgrading are reached, increasing the fractional volume occupied by gas in the well pair and in the interwell pore space.

The injection pressure is typically limited to the range 2,000-3500 kPa (-300-500 psi) to remain below formation fracture pressure and ensure gas containment for most oil sands reservoirs. Obviously for deeper reservoirs the injection pressure to be used needs to be higher and this would further increase the efficiency of the in situ upgrading process.

Steady State Operations

Once an interwell temperature of 350° C. is reached, injection of bitumen and vacuum residue (or other heavy hydrocarbons) with hydrogen and hydrocracking catalysts commences.

Surface hydrocracking catalysts generally operate at high residue conversion rates, as high as 90%, and consume 200-250 standard m³ (standard conditions: temperature: 15° C.; and pressure: 101.325 kPa) of hydrogen per m³ of residue, with inlet hydrogen concentrations at an excess of approximately 3 times the consumption rate (˜650 standard m³ of hydrogen per m³ of residue). The upgrading conditions outlined are for a 50% residue conversion, requiring hydrogen consumption of only 40-60 standard m³ of hydrogen per m³ of residue. Injected hydrogen is also estimated at 3 times the consumption rate, or 150 standard m³ of hydrogen per m³ of bitumen. Hydrogen injection in the process of the present disclosure can be injected all at once with the catalyst containing residue, or split into two fractions wherein typically about 1/3 of the total injected with the residue and 2/3 bubbling from a liner that would be attached at the top of the producing well in order to enrich the upgrading zone with bubbling hydrogen.

Ideally, hydrogen partial pressure is maintained higher than 2,500 kPa (360 psi) for effective reaction kinetics. The excess hydrogen conditions described above will ensure sufficient hydrogen partial pressure in the injection well, the upgrading zone and the production fluids.

At injection conditions of 350° C. and 3,450 kPa, gas volumes are reduced by approximately 15 times from standard conditions. In addition, 5 to 10% of the injected hydrogen volume is expected to dissolve in oil. Thus, assuming that the mixture will flow as a dispersion of gas in the oil (i.e. a bubbling regime) or in a mixed bubbling-slug flow regime, then the gas holdup fraction will be around the same as the flowing fraction of oil. Therefore, the fractional volume occupied by gas in the injection well will be 50% or lower.

In the upgrading zone, approximately one third of injected hydrogen is consumed. Other gases are produced by various mechanisms (particularly: methane, oil vapors, steam from connate water and hydrogen sulphide). Therefore, the fractional gas volume can be expected to increase through the upgrading zone. The fractional gas volume in the interwell upgrading zone will be higher than 25%.

The gas to liquids ratio in the production well is also expected to be similar to the conditions in the injection well.

The shape of the upgrading and recovery chamber 12 is expected to be a more elliptical shape than a conic shape as in SAGD processes. Given that vertical permeability is generally only 0.2 to 0.5 of horizontal permeability within the formation, the lateral dimension of the interwell upgrading zone will normally be greater than the vertical interwell distance. Factors governing the growth rate and shape of the chamber can be assessed by numerical and physical modeling.

Residence time in the well bores will typically be approximately 1 hour each, but will depend on the flow rate of injected bitumen. However, in the interwell region residence time will depend on factors such as:

-   -   a. Porosity (typically about 30%)     -   b. Fractional liquids volume (typically about 75%)     -   c. Lateral movement of injected liquids (typically about 5 to 10         m in each direction); and     -   d. Flow rate of injected bitumen and atmospheric residue.

Residence time in the interwell reaction zone will be approximately 50 to 500 hours (typical), matching or exceeding the requirements of the reaction kinetics for the current hydrocracking catalyst as in U.S. Pat. No. 7,897,537.

The injection rate may be a constant volumetric rate but production is generally set to maintain constant pressure in the reaction chamber. Normally, the liquids production rate will be higher than the injection rate because of oil volume expansion from hydrogen addition and incremental recovery from the upgrading formation.

Some upgrading will occur in the wells, but most will occur in the upgrading zone in the subterranean reservoir. Hydrogen addition upgrading is an exothermic process and can typically increase the oil temperature by approximately 40° C. in the reaction zone. This exothermic process more than compensates for local heat losses and maintains the upgrading zone at upgrading temperatures. The heat of hydrocracking reactions ranges from 42 to 50 kJ per mole of hydrogen and is also exothermic.

The upgrading zone at 350° C. will, over time, heat by conduction the surrounding bitumen formation, reducing the viscosity of the surrounding bitumen and making the bitumen mobile. Some of the surrounding bitumen, particularly from zones above the chamber, will flow by gravity through the upgrading zone to the production well and will be replaced by rising hydrogen and produced gas. Therefore, the recovery zone will grow in size from incremental recovery.

Importantly, during catalytic upgrading processes, as a result of increased chamber temperatures and the upgrading reactions, a greater proportion of the heaviest molecules that would otherwise remain adhered to the formation sand during recovery by conventional methods such as a SAGD process will be mobilized for recovery.

Upgrading will generate light oil fractions that will rise above the upgrading zone with hydrogen and produced gas. These very hot hydrocarbon vapors will act as solvents and further reduce bitumen viscosity in addition to causing thermal effects. The quantity of hydrocarbon vapors available may be augmented by recycling distillates from the column.

Incremental recovery and chamber growth will be driven by vapor extraction, gravity drainage, and gas displacement. Heat losses and availability of hydrocarbon vapors are two factors that will drive incremental recovery. A typical estimate of bitumen recovery from the upgrading formation is 50 barrels per day per 100 m of well length as known to those skilled in the art.

Heat losses will be significantly less than typical SAGD heat losses because:

-   -   a. latent heat of hydrocarbons is less than that of steam; in         addition, most of the heat transfer will be by conduction which         is less effective than convection;     -   b. the vapor chamber above the upgrading zone will have light         gases (e.g. H₂, CH₄) and condensed water that form an insulation         layer between the upgrading zone and the overburden; and,     -   c. the vapor chamber size and surface area for heat transfer         will be typically less than in a comparable SAGD system.

Furthermore, gas in the production fluid will provide gas lift, and no water is injected and no typical SAGD chamber is formed. At the end of upgrading or during interrupted upgrading operations, bitumen in the upgrading well pair can be recovered by SAGD (if implemented) due to the presence of the horizontal well pair and pad level steam generation capacity (if implemented).

Alternatively, the location of the upgrading well pair may be in a neighboring thin bitumen zone that would not be otherwise utilized or recovered.

Mass Balance Considerations

In considering the mass balance of the system based on typical operating conditions as described above, vacuum residue (or other heavy hydrocarbon) is injected and circulated through the interwell reaction zone at an oil rate of up to 10 times faster than the flow rate of steam of a typical SAGD process. However, the absence of condensed steam means that the liquids rate is only 2.5 times SAGD.

Hydrogen injected at three times excess over consumption requirements ensures sufficient hydrogen partial pressure (2600 kPa) for effective reaction kinetics. Hydrogen incorporation gradually reduces hydrogen concentration and volume by up to one third. Excess hydrogen conditions and production of other gases offset hydrogen consumption and maintain fractional gas volume at approximately 90%.

Injected catalyst flows with the injected oil. Some catalyst particles will be deposited on sand in the upgrading zone while some exit with produced fluids.

Bitumen made mobile by vapor extraction, heat losses and gas displacement flows downward under the effect of gravity. Hydrogen, light hydrocarbon vapors and other gases (CH₄, H₂S and steam from connate water) rise into the recovery zone.

Liquids production is composed of upgraded bitumen and atmospheric residue swelled by hydrogen addition and recovered bitumen. Therefore, liquids production is greater than liquids injection.

Energy Balance Considerations

For surface processing, thermal energy is required to heat bitumen to 320° C., operate the distillation column and deliver residue at 320° C. (FIG. 6). Heat exchangers are deployed to maximize energy efficiency by cooling hot fluids (i.e. upgraded oil being sent to the market) with cold fluids (i.e. incoming bitumen). These heat exchangers may be incorporated into the mobile surface reservoir. E.g. an oil tanker may comprise two reservoirs in thermal communication but not in fluid communication to allow heat to flow from a reservoir holding refined upgraded oil to a reservoir holding heavy hydrocarbons for injection into an injection well.

Further surface energy requirements include:

-   -   a. energy to operate the recycled gas compressor and to         re-establish pressure and flow in the recycled gas;     -   b. energy for hydrogen production and gas treatment;     -   c. energy to compress make up hydrogen to injection pressure if         required; and,     -   d. heat losses in the injection well.

The thermal energy supply includes bitumen and atmospheric residue at 300° C. being circulated through the upgrading zone. A fraction of the thermal energy contained in the circulating fluid is lost due to formation by conduction and convection (vaporization of light oil fractions). These heat losses heat surrounding bitumen and drive incremental bitumen recovery. Furthermore, upgrading reactions in the reaction zone generate thermal energy that offset heat losses and maintain the reaction zone at the desired temperature of 280-320° C.

Subterranean thermal energy requirements include maintenance of the upgrading zone at 280-320° C.; vaporization of light oil fractions; heating of porous media and bitumen for mobilization; heating of recovered bitumen to the upgrading temperature; and vaporization of connate water.

Temperature Distribution Considerations

FIG. 5 shows the temperature distribution considerations for the RAISUP and RAISCUP processes. The surrounding formation 56 has a temperature gradient ranging from 10° C. closest to the surface to bitumen mobilization temperature (˜100° C.) near the recovery zone. The recovery zone 42 ranges in temperatures from bitumen mobilization temperature to 300° C. The upgrading zone 40 is typically maintained at a temperature between 280° C. and 320° C. Exothermic reactions generate thermal energy and the temperature increases from the heat of the reaction. The temperature is decreased by the flow of colder bitumen from the recovery zone.

The inlet temperature of the injection well 16 is that of the injected fluids, i.e. approximately 300° C. The outlet temperature of the recovery well 18 is that of the produced fluids, i.e. approximately 280° C.

Surface Process and Facilities

FIG. 6 is a schematic diagram of the layout of potential surface facilities in accordance with the present disclosure. These surface facilities may be split between mobile components (e.g. associated with the mobile surface reservoir) and stationary components (e.g. associated with the well apparatus).

As shown, two well pairs are included with a layout as described by FIG. 3A. That is a first well pair 13 a is a typical SAGD well pair that is subjected to standard steam injection by steam plant 60. A second well pair 13 b is subjected to the RAISCUP process. Fluids recovered from the first well pair can be combined with the fluids from the second well pair.

Most of the gas stream from the production well, predominantly excess hydrogen, is recirculated 32 with a purge gas stream 60 sent to gas treatment 62. The purge gas stream 60 is used to control the concentration of produced gas components (i.e. C₁-C₄ gases, H₂S, CO—CO₂) in the recycled gas. Water may need to be removed prior to recompression.

Liquids are sent to the distillation column 20. Upgraded oil 34, with higher than 20° API is sent to the market 34 a. Diluent 34 b, 64 may be added to the upgraded oil.

Alternatively, or in addition, distillates/diluent stream 64 can be recovered separately and recycled to the upgrading well pair in order to increase the amount of hydrocarbon vapors available for vapor extraction and control the extent of bitumen recovery. In addition, distillates/diluent may be recovered for sales 64 a.

The distillation column 20 produces residue 26 that was unconverted in the upgrading chamber together with recovered catalyst that was not retained within the upgrading chamber. This residue 26 is recycled to the upgrading well pair through residue conditioning 26 a. This residue is stored temporarily in the mobile surface reservoir 10. It will be appreciated that, in some embodiments, the residue conditioning may take place in the mobile surface reservoir. It will be appreciated that the residue conditioning may take place in a pre-mixer configured to mix the heavy fraction with additional injection fluids and to inject the mixed fluids into the injection well.

Bitumen 22, from adjacent SAGD well pairs 13 a is mixed with residue 26 with hydrogen 28 and catalyst 30. The combined stream is added to recycled gas 32, and injected into the upgrading well pair 13 b.

A heat exchanger may be used to pre-heat the incoming bitumen 22 and diluent 24 with the upgraded oil 34 being sent to the market.

A recycle gas compressor 68 is required to re-establish appropriate pressure and flow rates in the recycled gas. A compressor 28 a for makeup hydrogen may also be required.

Process Control Elements and Improvements Rate of Bitumen Injection

The rate of bitumen injection determines the volume upgraded but also the rate of thermal energy addition to the formation. Thermal energy comes from heat losses incurred by bitumen-residue injected at 350° C., but also by heat generated in situ by hydrocracking reactions. This variable also determines the rate of light oil fractions available for solvent extraction. Therefore, this variable controls:

-   -   a. the production rate of upgraded oil;     -   b. the rate of incremental recovery; and     -   c. the growth rate of the reaction chamber.

Location of Injection and Production

The start-up configuration is injection from the top well and production from the bottom well. However, this configuration can be reversed and cycled to control:

-   -   a. temperature distribution in the reaction chamber;     -   b. catalyst distribution;     -   c. shape of the reaction chamber; and     -   d. the rate of incremental recovery.

Top Injection Well and Bottom Production Well

After start-up, the conventional configuration for a well pair is a top injection well and a bottom production well because this configuration minimizes the amount of pay zone that is below the production well. As is understood, pay zone below the production well is not recovered as the movement of oil and catalyst from the injection well to the production well follows the direction of gravity. Oil vapors produced in the interwell region are allowed to rise in the recovery zone.

Bottom Injection Well and Top Production Well

In an alternate embodiment, a bottom injection well and top production well configuration maximizes the temperature of the interwell reaction zone. Formation bitumen that is mobilized from zones above the chamber is at temperatures lower than 350° C. because mobilization starts at temperatures as low as 150° C. Excessive incremental bitumen recovery may quench the temperature of the reaction zone. With the top well being the producer, recovered bitumen is produced immediately when it reaches the top producing well and does not cool the interwell region. The temperature of the interwell region may rise higher than the injection temperature because of the heat generated by the upgrading reactions, and a hotter interwell zone maximizes upgrading. Furthermore, hydrogen rises through the interwell reaction zone.

Hydrogen Injection from a Tubing String inside the Bottom Production Well

Excess hydrogen conditions are specified to ensure that sufficient hydrogen is present throughout the process. However, hydrogen is a very light gas and the amount that may flow down from the top injector to the bottom producer may be less than required. In this event, secondary hydrogen injection can be provided through a tubing string inserted in the bottom producer, thereby replenishing hydrogen supply in the wellbore surrounding the bottom producer and inside the production well.

Electrical Heating

In a further embodiment, electrical heaters or other heating technologies may be used to increase the amount of supplied thermal energy if this would result in improved performance.

Shutdown and Restart Strategies

Unplanned interruption of operations would likely cause liquids to accumulate at the bottom of the vertical well where they could cool and solidify in the event of an extended interruption. Therefore, effective temperature measurement and control is desired throughout both injector and production wells. Prompt injection of VGO during an unplanned interruption of operation would likely avoid adverse consequences and also allows steam replacement as indicated above.

Modeling Results

Modeling results of the RAISUP and RAISCUP processes show that at 350° C., upwards of 50% of the vacuum residue can be upgraded based on a residence time longer than 16 hours. The resulting recovered and upgraded oil has a specific gravity of 16 API or greater, with a viscosity lower than 200 cP (at 25° C.). Table 1 shows mass balance data for a typical catalytic upgrading process with a residence time of less than 24 hours at 50% vacuum residue conversion, with hydrogen consumption of 9 Nm³/bbl and catalyst consumption of 0.10 tpd, excluding catalyst recovery.

TABLE 1 Mass Balance Data for Catalytic Upgrading Process (Modeled) Characteristic Bitumen Product Upgraded Oil Volume (bpd) 2625 2690 API gravity 8 16 Viscosity at 40° C. (cP) 20,000 225 Sulfur (w %) 5 3 Metal (ppm) 600 20 Asphalt (w %) 16 14 Microcarbon, μC (w %) 11 9 Total Acid Number (mg KOH/g) 5 <1

Table 2 shows modeled heat balance data for a catalytic upgrading process.

TABLE 2 Heat Balance Data for Catalytic Upgrading Process (Modeled) Vacuum Variable Residue at Start Recovered Bitumen Volume (bpd) 2500 1000 Volumetric Flow Rate (m³/s) 0.0046 0.00184 Specific Heat Capacity @ 2346.2 1997.104 300° C. (J/kg° C.) Average Density (kg/m³) 1077.8 920 Temperature in (° C.) 380 10 Temperature out (° C.) 296.6 297.0 Rate of Heat Transfer (W) 970,192.1 −970,192

Table 3 shows heat balance data for a typical SAGD process for comparison.

TABLE 3 Heat Balance Data for a Typical SAGD Process Bitumen Variable in Typical SAGD Process Volume (bpd) 1000 Volumetric Flow Rate (m³/s) 0.00184 Specific Heat Capacity @ 300° C. (J/kg° C.) 1997.1 Average Density (kg/m³) 920 Temperature in (° C.) 10 Temperature out (° C.) 162.1 Rate of Heat Transfer (W) −514,274

Table 4 shows recoverable heat from a modeled catalytic upgrading process.

TABLE 4 Recoverable Heat from Upgraded Oil in Catalytic Upgrading Process (Modeled) Variable Upgraded Oil Volume (bpd) 1000 Volumetric Flow Rate (m³/s) 0.00184 Specific Heat Capacity @ 300° C. (J/kg° C.) 1500 Average Density (kg/m³) 750 Temperature in (° C.) 297 Temperature out (° C.) 40 Rate of Heat Transfer (W) 532,027.8 Deasphalted Oil Assisted In situ Catalytic Upgrading (DAISCU)

A variation of the RAISCUP process is deasphalted oil assisted in situ catalytic upgrading process (DAISCU). In this embodiment, and with reference to FIG. 7 bitumen 22 recovered from the well pair 13 is subjected to deasphalting processes to create deasphalted oil (DAO) that is used as an upgradable heat carrier for injection and pitch wherein a portion of the pitch is used as a fuel (the fuel portion) and another portion (the non-fuel portion) of the pitch is re-mixed with DAO for injection. Generally, the relative proportion of the fuel portion to the non-fuel portion is dependent on the degree of upgrading being achieved wherein the proportion will change as the reservoir is approaching the target temperature in the upgrading zone. In the present case, the RAISCUP may be initiated by injecting fluid heavy hydrocarbons into the well from a mobile surface reservoir.

In DAISCU, initially during the creation of the upgrading chamber, bitumen is mobilized and produced by an introduced hot fluid in order to create an incipient upgrading chamber in a manner similar to the start-up of RAISUP. During this stage, the produced bitumen is stored in a large tank 82 until enough oil is assured to start a solvent deasphalting operation (SDO) that will produce deasphalted oil (DAO) and pitch as well as a sufficient increase in the temperature of the DAO to the upgrading reaction temperature of ˜320° C.

More specifically, recovered fluids 81 (containing bitumen and upgraded oil) are introduced into a submicronizer system 80 for creating very small particles of the recovered bitumen. The recovered fluids are then pumped to the storage tank 82 having a sufficient volume to collect and store recovered fluids for subsequent processing. Gas 85 from the storage tank may be subject to gas treatment 62. Upon a suitable volume of recovered fluids having been collected, upgraded oil products 34 (from distillation column, not shown) are collected and delivered to market.

Heavier fractions 84 a, containing substantially heavier fractions, will be introduced into a solvent deasphalting unit 86, which by solvent addition forms a deasphalted oil fraction (DAO) 87 and heavier asphalt/pitch fractions 88 a (fuel fraction) and 88 b (non-fuel fraction) will depend on the relative progress of the upgrading chamber and upgrading reactions. The fuel portion 88 a is delivered to furnace 90 wherein the fuel portion is burned together with recovered gases 62 a from gas treatment 62 to heat DAO 87 for injection into well 16.

The non-fuel portion 88 b may be returned to micronizer 80 and storage system 84.

The heated DAO may be combined with hydrogen 28 and catalyst 30 as described above at injection.

With reference to FIG. 8, the upgrading zone is described in relation to DAISCU processes. The recovery chamber is similar to that of FIGS. 1, 2, 3 and 4. As shown, both the upper and lower wells enable hydrogen injection and DAO is injected into the upper injection well. The upgrading zone can be generally described as having three regions. In the first region (a), hydrogen, catalysts and DAO are injected at reaction temperature. Generally, the injector well volume will determine a residence time in the order of 0.5 to 3 hours, such that a relative minor degree (approximately 10%) of upgrading will occur.

The second region (b) extends immediately below the injector well and towards the production well. In a mature well, a significant amount of bitumen has already been produced, thus the zone can be described as having a higher degree of injectivity in comparison to other zones insomuch as flow is enabled between the injector and production wells. As such, injected DAO will predominantly flow downwardly and be upgraded to a significant extent due to the reaction conditions in this zone.

Bitumen in the region above the injector well flows downwardly as a result of dissolution and convective heat being transferred by volatile hydrocarbon vapors and gases produced during upgrading, by the hydrogen injected but also by overheated steam formed from connate water. All these gases tend to concentrate and reflux at the top of the chamber carrying heat and solvent capabilities to assist in mobilizing bitumen downwards towards the production well. Thus, bitumen from above the injector well is also upgraded with zone (b).

Bitumen conductively heated by the DAO adjacent the lateral walls of the interwell region is also mobilized and is significantly upgraded as it mixes with the DAO carrying catalysts near the production well and in contact with the hydrogen flow emanating from hydrogen liner(s) externally attached to the upper hemisphere of the production well.

The third region, zone (c), is located around the production well and provides additional volume and, hence residence time for completing upgrading before the produced oil reaches the surface or the temperature drops below the reaction temperature.

Nano-Catalytic In situ Upgrading (n-CISU)

In a further embodiment, and with reference to FIG. 9, a nano-catalytic in situ upgrading (n-CISU) technology is described. The n-CISU process can be applied to a simple well configuration using huff and puff extraction. In this embodiment, a vertical well 13 c can be utilized in which hot fluids (i.e. including oil) from a mobile surface reservoir together with other additives including hydrogen 28 and catalyst 30 are pumped into the well. After injection, the well is sealed and pressurized for a soak time to allow in-situ upgrading to occur. After a sufficient soak time, the pressure is released and fluids (including upgraded oil 80) are pumped from the well. The cycle can be repeated as long as the well is productive. This may allow the mobile surface reservoir to be emptied into the well before receiving the processed product into the mobile surface reservoir. This may help prevent the pre-processing hydrocarbons being mixed with the post-processed hydrocarbons in the mobile surface reservoir.

In greater detail, the start-up and production phases may be achieved in the following representative description. Initially, hot fluid 60 from a mobile surface reservoir is used to preheat the reservoir zone around a vertical well 13 in accordance with normal huff and puff procedures. During this phase, preliminary quantities of oil/bitumen 80 will be produced from the well and stored in a heated tank 62 (T˜80-140° C.) for later use. Once enough injectivity has been created (if initially non-existent), the stored oil 62 a would be used for two purposes, first to disperse nano-catalysts 30 (at an approximate concentration of 600 ppm) in that oil and second to convey heat to the reservoir at a typical injection temperature 270-290° C. Catalyst is injected once in the first injection cycle and in a small quantity. Any additional catalyst can be introduced during successive cycles to maintain catalyst concentration at a desired level. Hydrogen 28 is co-injected with the down-going oil (H₂/bitumen ratio 90 sm³/bitumen or oil m³).

The injected material is introduced at a pressure slightly above the reservoir pressure. Once sufficient hot oil has been injected (typically about 90% of the oil initially produced and stored during 10-15 days of initial production), a closed well period (soaking time) between 10 to 15 days is maintained. During the soak time, both the injected oil and the oil being recovered are upgraded.

During soaking, the pressure and gas composition of the well is monitored to ensure that favorable upgrading conditions are being maintained. Additional hydrogen may be added during the soak time as may be required to maintain reservoir pressure and to promote favorable reaction kinetics.

Hydrogen is typically consumed at a ratio of 15 sm³ per barrel of oil injected and produced. 45 sm³ of hydrogen per barrel of heated oil/bitumen injected may be consumed as a maximum, assuming oil productivity is doubled with respect to a standard huff and puff dry operation (highest expectation). Thus approximately 25 to 50% of the hydrogen injected would be consumed.

After the soak period, recovered fluids will be subjected to distillation in distillation column 20 to effect separation of upgraded oil for market 34 and recovery of gas components 85. As in previous embodiments, high viscosity components, including residue, may be re-injected into the well as the cycles are repeated.

The same general methodology can be applied to each of the well configurations as shown in FIG. 3B.

Other Comparison to SAGD

The methods and apparatus in accordance with the present disclosure can provide significant advantages over SAGD in terms of overall energy balance. As known, in a SAGD operation, heat is injected into the formation in the form of steam and is generally recovered as warm water. As such, at surface, water is heated utilizing significant amounts of fossil fuel energy to create the necessary volumes, pressures and temperature of steam for downhole injection. Specifically, the amount of energy required to heat water to steam requires the energy of the heat of vaporization of water to create steam. While the energy of the heat of vaporization of water is input into the reservoir as the steam condenses to water, the water returns to surface as a contaminated water/mineral/hydrocarbon stream that requires significant treatment prior to being reheated to steam. Specifically, the mineral contaminants must be removed to prevent scaling in the steam generation equipment, and the hydrocarbon must be separated from the water.

As is understood, the energy cost of removing mineral/hydrocarbon contaminants from water has an associated energy requirement that is significantly reduced with the subject technology as the volume of water recovered from the formation will be significantly less as generally the only water present in the system will be connate water. After hydrocarbon separation, no additional water treatment may be required.

As such, the environmental impact of the subject technology is significantly lower as significantly lower volumes of water are required for the process. The elimination of settling ponds could be achieved.

Furthermore, as the in situ upgrading reactions are exothermic reactions, the requirement for heat input at surface is reduced.

Carbonate Formations and Enhanced Oil Recovery in Conventional Reservoirs

The technology may also be applied to other formations beyond heavy oil reservoirs including conventional reservoirs that may be declining in production, deeper reservoirs than oil sands which are relatively shallow, and carbonate formations. In particular, as compared to SAGD which can generally only be applied to relatively shallow type reservoirs, the subject methodologies can be applied to other formations as an enhanced oil recovery technique.

The additional oil recoverable with the hot fluid injection method may be 10 to 30% higher than the one recovered via steam stimulation, which are significantly higher recovery rates than from steam injection technologies. Moreover, the oil produced with the subject technologies can reach transportable level (μ<280 cPoises @ 25° C.) for bitumen embedded sands, with minimal to no reduction in permeability of the reservoir and with at least similar recovery of oil.

As a result, the technologies can lead to the elimination of upgrading facilities to enable transportation and/or diluent needs.

Although the present invention has been described and illustrated with respect to preferred embodiments and preferred uses thereof, it is not to be so limited since modifications and changes can be made therein which are within the full, intended scope of the invention as understood by those skilled in the art. 

1. An apparatus for processing hydrocarbons, the apparatus comprising: an injection well, the injection well being configured to inject fluid into a subterranean reservoir; a recovery well, the recovery well being configured to recover fluid from the subterranean reservoir; and an injection well connector configured to receive heavy hydrocarbon fluid from a mobile surface reservoir and deliver the received heavy hydrocarbon fluid to the injection well to be injected into the subterranean reservoir for processing such that the fluid recovered from the subterranean reservoir via the recovery well has a different composition to the heavy hydrocarbon fluid injected via the injection well.
 2. The apparatus according to claim 1, wherein the mobile surface reservoir forms part of an oil tanker ship.
 3. The apparatus according to claim 1, wherein the apparatus forms part of an offshore oil rig.
 4. The apparatus according to claim 1, wherein the heavy hydrocarbons comprise one or more of: bunker fuel; and fuel number
 6. 5. The apparatus according to claim 1, wherein the apparatus comprises a pre-mixer configured to mix the heavy fraction with additional injection fluids and to inject the mixed fluids into the injection well.
 6. The apparatus according to claim 1, wherein the injection well is configured to inject a portion or all of the heavy residual hydrocarbon fractions at a temperature and pressure to promote hydrocarbon upgrading reactions in the subterranean reservoir.
 7. The apparatus according to claim 1, wherein the apparatus comprises a recovery well connector configured to enable at least a portion of the recovered hydrocarbons from the recovery well to be delivered to the mobile surface reservoir.
 8. The apparatus according to claim 1, wherein the injection well and recovery well are operatively connected to a hydrocarbon distillation column for separation of recovered fluids from the recovery well into heavy and light fractions.
 9. The apparatus according to claim 1, wherein the apparatus comprises a solvent deasphalting separation configured to subject the hydrocarbons recovered from the recovery well to a solvent deasphalting separation process to form a deasphalted oil and an asphaltic pitch.
 10. The apparatus according to claim 1, wherein the apparatus comprises a heater, the heater configured to heat the heavy hydrocarbons received from the mobile surface reservoir before they are injected into the subterranean reservoir.
 11. A mobile storage container comprising: a mobile surface reservoir for storing heavy hydrocarbons, the storage container configured to enable fluid communication with an injection well such that heavy hydrocarbons contained in the mobile surface reservoir can be injected into a subterranean reservoir via the injection well for processing; and a drive means configured to provide energy for locomotion of the mobile reservoir.
 12. The mobile storage container according to claim 11, wherein the mobile surface reservoir is configured to provide at least some of the stored heavy hydrocarbons to the drive means as fuel.
 13. The mobile storage container according to claim 11, wherein the mobile storage container comprises one or more of: a hydrogen source, configured to introduce hydrogen into the heavy hydrocarbons prior to injection into the injection well; a catalyst skid configured to introduce catalyst into the heavy hydrocarbons prior to injection into the injection well; a heater configured to heat the heavy the heavy hydrocarbons prior to injection into the injection well.
 14. The mobile storage container according to claim 11, wherein the mobile storage container comprises a fractional distillation column configured to separate fractions of hydrocarbons obtained from the recovery well.
 15. A system, the system comprising the apparatus of claim 1, and a storage container comprising: a mobile surface reservoir for storing heavy hydrocarbons, the storage container configured to enable fluid communication with an injection well such that heavy hydrocarbons contained in the mobile surface reservoir can be injected into a subterranean reservoir via the injection well for processing; and a drive means configured to provide energy for locomotion of the mobile reservoir.
 16. A method for processing hydrocarbons, the method comprising: transporting heavy hydrocarbons from a remote location to an injection well site; injecting the heavy hydrocarbons into a subterranean reservoir via an injection well for processing; recovering hydrocarbons from the subterranean reservoir via a recovery well, wherein the fluid recovered from the subterranean reservoir via the recovery well has a different composition to the heavy hydrocarbon fluid injected via the injection well.
 17. The method according to claim 16, wherein the heavy hydrocarbons are transported by a mobile surface reservoir.
 18. The method according to claim 17, wherein mobile surface reservoir is configured to receive at least a portion of the hydrocarbons recovered from the recovery well.
 19. The method according to claim 16, wherein the heavy hydrocarbons are transported by a mobile surface reservoir configured to consume some of the heavy hydrocarbons as an engine fuel for locomotion.
 20. The method according to claim 16, wherein the heavy hydrocarbons are transported by pipeline.
 21. The method according to claim 16, wherein the transported heavy hydrocarbons are injected into the injection well to initiate processing of hydrocarbons already present in the subterranean reservoir.
 22. The apparatus according to claim 1, wherein the apparatus forms part of an offshore oil rig and the mobile surface reservoir forms part of an oil tanker ship; wherein the heavy hydrocarbons comprise one or more of bunker fuel and fuel number 6; wherein the apparatus comprises a pre-mixer configured to mix the heavy fraction with additional injection fluids and to inject the mixed fluids into the injection well; wherein the injection well is configured to inject a portion or all of the heavy residual hydrocarbon fractions at a temperature and pressure to promote hydrocarbon upgrading reactions in the subterranean reservoir; wherein the apparatus comprises a recovery well connector configured to enable at least a portion of the recovered hydrocarbons from the recovery well to be delivered to the mobile surface reservoir; wherein the injection well and recovery well are operatively connected to a hydrocarbon distillation column for separation of recovered fluids from the recovery well into heavy and light fractions; wherein the apparatus comprises a solvent deasphalting separation configured to subject the hydrocarbons recovered from the recovery well to a solvent deasphalting separation process to form a deasphalted oil and an asphaltic pitch; and wherein the apparatus comprises a heater, the heater configured to heat the heavy hydrocarbons received from the mobile surface reservoir before the heavy hydrocarbons are injected into the subterranean reservoir. 